The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
Wellbore stimulation is a widely practiced treatment method to enhance the production of hydrocarbons from oil or gas wells traversing subterranean reservoirs by removing near-wellbore formation damage or by creating alternate flow paths through the formation. Stimulation operations often involve injecting a stimulation fluid into an isolated treatment zone at pressures below the fracture pressure of the formation. In some instances, the injected fluid may extend the effective wellbore drainage radius by dissolving formation rock to form channels such as wormholes or remove formation damage induced during drilling operations. The purpose of such stimulation techniques is often to increase the production rate by increasing the near borehole equivalent permeability.
Wellbore stimulation methods may include hydraulic fracturing, acidizing, or a combination of both called acid fracturing. In hydraulic fracturing, the stimulation fluid may be referred to as fracturing fluid, while fluids used in acidizing the latter may be referred to as an acidizing fluid or simply as acid. In hydraulic fracturing, a fluid is pumped from the surface into a wellbore at a pressure and rate sufficient to open fractures in the rock. During acidizing treatments, the acid or acid mixture is injected from the surface into the reservoir to dissolve materials that impair well production or to open channels or wormholes in the formation. When combining both methods, it is the role of the acid to etch away from the surface of the fractures to prevent them from closing completely once the pumping pressure is released.
However, while stimulation treatments may be used to enhance the well productivity by creating alternative flow paths through isolated regions of the formation, computer modeling of flow path formation may be hindered by reservoir properties that have not been taken into account. For example, properties such as the pore-scale heterogeneity of carbonates may have certain effects on the movement of injected stimulation fluids into the formation as alternative flow paths are created.